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BRY > SEC Filings for BRY > Form 10-K on 28-Feb-2013All Recent SEC Filings

Show all filings for BERRY PETROLEUM CO

Form 10-K for BERRY PETROLEUM CO


28-Feb-2013

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with Item 6. Selected Financial Data and the accompanying financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains forward looking statements that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially because of a number of risks and uncertainties. Some of these risks and uncertainties are detailed in Part I, Item 1A. Risk Factors, and elsewhere in this Annual Report on Form 10-K.

Overview

We are an independent energy company engaged in the production, development, exploitation and acquisition of oil and natural gas. We were incorporated in Delaware in 1985. We have been publicly traded since 1987 and trace our roots in California oil production back to 1909. Since 2002, we have expanded our portfolio of assets through selective acquisitions driven by a consistent focus on properties with proved reserves and significant growth potential through low-risk development. Our principal reserves and producing properties are located in California, Texas (Permian and E. Texas), Utah (Uinta) and Colorado (Piceance).

Our revenue, profitability and future growth rate depend on many factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices have been volatile and may fluctuate widely in the future. The following charts highlight the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2010:

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Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and natural gas that we can produce economically and therefore potentially lower our oil and natural gas reserves. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved oil and natural gas properties and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity or ability to finance planned capital expenditures. Lower oil and natural gas prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil prices may result in significant non-cash fair value losses being incurred on our oil derivatives, which could cause us to experience net losses when prices rise.

Steam costs are a significant variable component of our operating costs and fluctuate based on the amount of steam we inject and the price of natural gas used to generate steam. We benefit from lower natural gas prices as a consumer of natural gas in our California operations. In the Permian, Uinta, E. Texas and Piceance, we benefit from higher natural gas pricing as a producer of natural gas. In addition, production rates, labor and equipment costs, maintenance expenses and production taxes influence our operating costs. Our results of operations may fluctuate from period to period based on such factors.

LinnCo, LLC Merger

On February 20, 2013, the Company, Linn Energy, LLC (Linn), LinnCo, LLC (LinnCo), Linn Acquisition Company, LLC, a direct wholly owned subsidiary of LinnCo (LinnCo Merger Sub), Bacchus HoldCo, Inc., a direct wholly owned subsidiary of the Company (HoldCo), and Bacchus Merger Sub, Inc., a direct wholly owned subsidiary of HoldCo (Bacchus Merger Sub), entered into a definitive Agreement and Plan of Merger (the "Merger Agreement"), pursuant to which LinnCo agreed to acquire


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the Company in an all-stock transaction in which the Company's stockholders would receive 1.25 shares representing limited liability company interests in LinnCo (LinnCo Shares) for each share of the Company's common stock.

The transaction will occur through multiple steps. First, the Company will engage in a holding company merger (the HoldCo Merger) involving HoldCo and Bacchus Merger Sub. In the HoldCo Merger, Bacchus Merger Sub will merge with and into the Company, with the Company surviving as a wholly owned subsidiary of HoldCo, and each issued and outstanding share of the Company's Class A common stock and Class B common stock will convert into the right to receive one equivalent share of Class A common stock and one equivalent share of Class B common stock, respectively, of HoldCo.

Second, promptly after the HoldCo Merger, the Company will be converted into a limited liability company. Third, promptly following such conversion, HoldCo will be merged with and into LinnCo Merger Sub, with LinnCo Merger Sub surviving as the surviving company (the LinnCo Merger). In the LinnCo Merger, each share of Holdco's Class A common stock and each share of Holdco's Class B common stock will be converted into 1.25 LinnCo Shares.

Finally, promptly following the LinnCo Merger, LinnCo will contribute all of the outstanding equity interests in LinnCo Merger Sub (and therefore also its indirect ownership interest in the Company) to Linn (the "Contribution") in exchange for the issuance to LinnCo (the "Issuance") of newly issued Linn common units. The number of Linn common units to be issued to LinnCo in the Issuance will be equal to the greater of (i) the aggregate number of LinnCo Shares issued in the LinnCo Merger and (ii) the number of Linn common units required to cause LinnCo to own no less than one-third of all of the outstanding Linn common units following the Contribution. In addition, for three years following the closing, Linn will pay to LinnCo additional cash distributions in the amount of $6 million per year.

The closing of the transactions is subject to customary closing conditions, including approval of the Merger Agreement and the transactions contemplated thereby by the stockholders of the Company and the holders of the shares of LinnCo and Linn, receipt of certain opinions by the parties with respect to the tax-free nature of the transactions, and other customary conditions such as expiration of the waiting period under the Hart-Scott-Rodino Act.

Notable Items - Full Year 2012

Increased oil production 11% from 2011, offsetting a 17% decrease in natural gas production and increasing oil production to 75% of total production in 2012

Generated an operating margin of $48.79 per BOE, supported by sales of our California heavy oil at a $8.93 average premium over WTI during 2012(1)

Generated discretionary cash flow of $501.7 million from production of 36,402 BOE/D(1)

Increased cash flow from operations by $45.5 million or 10% from 2011

Increased oil reserves 10% from 2011, replacing 283% of oil production in 2012

Increased oil reserves to 74% of total proved reserves

Acquired approximately 28,000 net acres in or contiguous to our core operating areas in the Uinta

Drilled 74 Permian wells and increased Permian production to 6,735 BOE/D, a 52% increase over 2011

Increased production from our NMWSS-New Steam Floods by 73% to 1,827 BOE/D

Drilled 102 Uinta wells and increased Uinta production to 6,133 BOE/D, an 11% increase over 2011

Received final US Forest Service approval on our Environmental Impact Study for the Ashley Forest in the Uinta

Drilled 120 Diatomite wells and increased Diatomite production from an intra-month low of 1,750 BOE/D during March 2012 to 4,090 BOE/D during December 2012; Diatomite production averaged 3,255 BOE/D for full-year 2012

Issued $600 million aggregate principal amount of our 6.375% senior notes due 2022 (2022 Notes) and used the proceeds to, among other things, redeem part of our 2014 Notes and all of our 2016 Notes

Notable Items - Fourth Quarter 2012

Increased total production 9% from the third quarter of 2012 to 39,500 BOE/D

Increased production from the third quarter of 2012 in the Uinta by 26% to 7,500 BOE/D, Permian by 16% to 7,965 BOE/D, NMWSS-New Steam Floods by 11% to 2,130 BOE/D and Diatomite by 10% to 3,855 BOE/D compared to the third quarter of 2012

Increased oil production to 78% of total production from the third quarter of 2012



(1) Operating margin and discretionary cash flow are non-GAAP measures and reference should be made to "Reconciliation of Non-GAAP Measures" in Item
2. Management's Discussion and Analysis of Financial Condition and Results of Operations for further explanation as well as reconciliations to the most directly comparable GAAP measures.


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Results of Operations.

We had net earnings of $171.5 million, or $3.09 per diluted share, for the year ended December 31, 2012. Net earnings included a $26.3 million loss on extinguishment of debt associated with repurchasing all $200 million aggregate principal amount of our 8.25% Senior subordinated notes due 2016 (2016 Notes) and $150 million aggregate principal amount of our 10.25% Senior notes due 2014 (2014 Notes), a gain on derivatives of $22.9 million resulting from non-cash changes in fair values and amortization of accumulated other comprehensive income (AOCL) related to de-designated hedges, an expense of $1.8 million related to principal and interest paid in connection with the settlement of disputed royalty payments, dry hole expense of $9.3 million, a $9.3 million cash settlement related to the early termination of our natural gas derivatives, a gain of $0.9 million related to a retroactive payment adjustment for capacity from one of our electricity customers and a $1.0 million gain associated with the sale of our Nevada Assets, in each case net of income taxes. Net earnings also included a $7.2 million benefit from our research and development tax credit. Net cash provided by operating activities was $501.4 million and capital expenditures, excluding capitalized interest and property acquisitions and divestitures, totaled $676.0 million. We drilled 431 net wells during 2012 and achieved average daily production of 36,402 BOE/D in 2012, an increase of 2% from 2011.

We had net earnings of $38.5 million, or $0.69 per diluted share, for the fourth quarter of 2012. Net earnings included a gain on derivatives of $1.0 million resulting from non-cash changes in fair values and amortization of AOCL related to de-designated hedges, dry hole expense of $8.6 million and a gain of $0.9 million related to a retroactive payment adjustment for capacity from one of our electricity customers, in each case net of income taxes. Net earnings for the fourth quarter also included a $7.2 million benefit from our research and development tax credit. Net cash provided by operating activities was $109.8 million and capital expenditures, excluding capitalized interest and property acquisitions and divestitures, totaled $151.9 million. We drilled 88 net wells during the quarter and achieved average daily production of 39,500 BOE/D, an increase of 9% over the third quarter of 2012, primarily due to increased oil production from the Uinta, the Permian and our California properties.


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Operating Data.

The following table sets forth selected operating data for the years ended:

                                        December 31, 2012     %      December 31, 2011     %      December 31, 2010     %
Heavy oil production (BOE/D)                      17,905       49              17,397       49              17,124       52
Light oil production (BOE/D)                       9,488       26               7,374       21               4,589       14
Total oil production (BOE/D)                      27,393       75              24,771       70              21,713       66
Natural gas production (Mcf/D)                    54,054       25              65,498       30              65,720       34
Total (BOE/D)(1)                                  36,402      100              35,687      100              32,666      100

Oil and natural gas, per BOE:
Average realized sales price           $           71.00            $           66.91            $           52.14
Average sales price including cash
derivative settlements                 $           72.18            $           65.68            $           53.84

Oil price, per BOE:
Average WTI price                      $           94.15            $           95.11            $           79.59
Price sensitive royalties(2)                       (3.36 )                      (3.60 )                      (3.06 )
Quality differential and other(3)                  (0.67 )                       0.84                        (8.92 )
Oil derivatives non-cash
amortization(4)                                    (1.09 )                      (6.77 )                      (2.59 )
Oil revenue per BOE                    $           89.03            $           85.58            $           65.02
Add: Oil derivatives non-cash
amortization(4)                                     1.09                         6.77                         2.59
Oil derivatives cash settlements(5)                 0.07                        (9.72 )                      (0.90 )
Average realized oil price per BOE     $           90.19            $           82.63            $           66.71

Natural gas price, per Mcf:
Average Henry Hub price per MMBtu      $            2.79            $            4.04            $            4.39
Conversion to Mcf                                   0.19                         0.28                         0.22
Natural gas derivatives non-cash
amortization(4)                                     0.01                         0.01                         0.08
Location, quality differentials and
other                                              (0.18 )                      (0.23 )                      (0.24 )
Natural gas revenue per Mcf            $            2.81            $            4.10            $            4.45
Add: Natural gas derivatives non-cash
amortization(4)                                    (0.01 )                      (0.01 )                      (0.08 )
Natural gas derivative cash
settlements(5)                                      0.22                         0.46                         0.37
Average realized natural gas price per
Mcf                                    $            3.02            $            4.55            $            4.74


___________________________________________


(1) Oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of oil.

(2) Our Formax property in S. Midway is subject to a price-sensitive royalty burden. The royalty is 53% of the amount of the heavy oil posted price above the 2012 base price of $17.43 per barrel as long as we maintain a minimum steam injection level. We met the steam injection level in 2012 and expect to meet the requirement going forward. The base price escalates at 2% annually and will be $17.78 in 2013.

(3) In California, the per barrel oil posting differential at December 31, 2012 was $11.02, ranged from $2.18 to $11.52 during 2012 and averaged $8.93 during 2012. In Utah, the per barrel oil posting differential at December 31, 2012 was ($15.50), ranged from ($12.49) to ($16.52) during 2012 and averaged ($15.63) during 2012.

(4) Non-cash amortization of AOCL resulting from discontinuing hedge accounting effective January 1, 2010. Recorded in the Statements of Operations under the caption oil and natural gas sales.

(5) Cash settlements on derivatives are recorded in the Statements of Operations under the caption realized and unrealized (gain) loss on derivatives, net.


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The following table sets forth selected operating data for the three months ended:

                                                                     December 31,            September 30,
                                         December 31, 2012     %         2011         %          2012          %
Heavy oil production (BOE/D)                       19,058       48       17,497      49          18,149         50
Light oil production (BOE/D)                       11,591       30        8,166      23           9,344         26
Total oil production (BOE/D)                       30,649       78       25,663      72          27,493         76
Natural gas production (Mcf/D)                     53,106       22       60,759      28          52,758         24
Total (BOE/D)(1)                                   39,500      100       35,790     100          36,286        100

Oil and natural gas, per BOE:
Average realized sales price            $           70.51            $    69.29             $     70.22
Average sales price including cash
derivative settlements                  $           72.47            $    68.80             $     71.45

Oil price, per BOE:
Average WTI price                       $           88.23            $    94.06             $     92.20
Price sensitive royalties(2)                        (2.65 )               (3.63 )                 (3.12 )
Quality differential and other(3)                    0.79                  4.75                   (0.68 )
Oil derivatives non-cash
amortization(4)                                     (1.03 )               (6.76 )                 (1.10 )
Oil revenue per BOE                     $           85.34            $    88.42             $     87.30
Add: Oil derivatives non-cash
amortization(4)                                      1.03                  6.76                    1.10
Oil derivative cash settlements(5)                   1.57                 (8.89 )                  0.64
Average realized oil price per BOE      $           87.94            $    86.29             $     89.04

Natural gas price, per Mcf:
Average Henry Hub price per MMBtu       $            3.41            $     3.54             $      2.80
Conversion to Mcf                                    0.24                  0.21                    0.19
Natural gas derivatives non-cash
amortization(4)                                         -                     -                    0.02
Location, quality differentials and
other                                               (0.14 )               (0.24 )                 (0.13 )
Natural gas revenue per Mcf             $            3.51            $     3.51             $      2.88
Add: Natural gas derivatives non-cash
amortization(4)                                         -                     -                   (0.02 )
Natural gas derivative cash
settlements(5)                                      (0.03 )                0.61                   (0.04 )
Average realized natural gas price per
Mcf                                     $            3.48            $     4.12             $      2.82


___________________________________________


(1) Oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of oil.

(2) Our Formax property in S. Midway is subject to a price-sensitive royalty burden. The royalty is 53% of the amount of the heavy oil posted price above the 2012 base price of $17.43 per barrel as long as we maintain a minimum steam injection level. We met the steam injection level in 2012 and expect to meet the requirement going forward. The base price escalates at 2% annually and will be $17.78 in 2013.

(3) In California, the per barrel oil posting differential at December 31, 2012 was $11.02, ranged from $9.83 to $11.04 during the fourth quarter of 2012 and averaged $10.37 during the fourth quarter of 2012. In Utah, the per barrel oil posting differential at December 31, 2012 was ($15.50), ranged from ($15.00) to ($15.50) during the fourth quarter of 2012 and averaged ($15.24) during the fourth quarter of 2012.

(4) Non-cash amortization of AOCL resulting from discontinuing hedge accounting effective January 1, 2010. Recorded in the Statements of Operations under the caption oil and natural gas sales.

(5) Cash settlements on derivatives are recorded in the Statements of Operations under the caption realized and unrealized (gain) loss on derivatives, net.


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The following table reflects our results of operations for the periods presented:

                                                       Year ended                                                     Three months ended
(in thousands, except per                                                                                                                      September 30,
share data)                  December 31, 2012      December 31, 2011      December 31, 2010       December 31, 2012      December 31, 2011         2012
Oil sales                  $           881,688     $         772,685     $           512,699     $           231,766     $         207,689     $    218,952
Natural gas sales                       55,573                98,088                 106,909                  17,145                19,609           13,964
Oil and natural gas sales  $           937,261     $         870,773     $           619,608     $           248,911     $         227,298     $    232,916
Electricity sales                       29,940                34,953                  34,740                   8,586                10,750            9,514
Natural gas marketing                    7,631                13,832                  22,162                   2,253                 2,550            1,939
Gain on sale of assets                   1,782                     -                       -                      12                     -              170
Settlement on Flying J
bankruptcy claim                             -                     -                  21,992                       -                     -                -
Interest and other income,
net                                      1,985                 1,784                   3,300                     307                   390              286
Total revenues and other
income                     $           978,599     $         921,342     $           701,802     $           260,069     $         240,988     $    244,825
Net earnings (loss)        $           171,539     $        (228,063 )   $            82,524     $            38,499     $        (414,733 )   $     18,126
Diluted net earnings
(loss) per share           $              3.09     $           (4.21 )   $              1.52     $              0.69     $           (7.62 )   $       0.33

Oil and Natural Gas Sales.

Oil and natural gas sales increased $66.5 million, or 8%, in 2012 compared to 2011. The increase was primarily due to a 6% increase in the average sales price in 2012 compared to 2011, largely as a result of an increase in oil sales volumes as a percentage of total sales volumes. Our oil sales volumes increased 10% in 2012 compared to 2011, while our natural gas sales volumes decreased 17%. The oil volume increase was primarily due to an increase in oil production from all of our oil properties except our legacy SMWSS-Steam Floods properties. In 2012, our oil production increased relative to 2011 as follows: Permian 1,800 BOE/D, or 48%; Uinta 440 BOE/D, or 14%; NMWSS-New Steam Floods 770 BOE/D, or 73%; and Diatomite 100 BOE/D, or 3%. These increases in oil production were partially offset by a decrease in production from our SMWSS-Steam Floods properties due to expected production declines. Additionally, the decrease in natural gas sales volumes was primarily due to expected production declines from our E. Texas and Piceance properties, partially offset by increased natural gas production from our Permian and Uinta properties. In addition to the increase in oil sales volumes, non-cash derivative losses decreased by $50.2 million related to de-designated commodity hedges reclassified from AOCL into oil and natural gas sales.

Oil and natural gas sales increased $251.2 million, or 41%, in 2011 compared to 2010. The increase was primarily due to a 28% increase in the average realized sales price and a 10% increase in sales volumes in 2011 compared to 2010. The increase in the average sales price was primarily due to a 19% increase in the average WTI price in 2011 compared to 2010. The increase in oil production as a percentage of total production from 2010 to 2011 also contributed to the increase in the average sales price over that time period. The increase in sales volume was primarily due to a 14% increase in oil sales volume in 2011 compared to 2010, largely due to increased oil production from the Permian, which increased 2,660 BOE/D, or 245%, from 2010 to 2011. Also increasing over the same period was Diatomite oil production, which increased 430 BOE/D, or 16%; NMWSS-New Steam Floods oil production, which increased 250 BOE/D, or 31%; and Uinta oil production, which increased 190 BOE/D, or 6%. These increases were offset by an increase in non-cash derivative losses of $42.5 million related to de-designated commodity hedges reclassified from AOCL into oil and natural gas sales.


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Electricity Sales.

The following table sets forth selected results of operations for the periods
ended:

                                                            Year Ended December 31,
                                                        2012          2011          2010
Electricity
Electricity sales (in thousands)                    $   29,940     $  34,953     $  34,740
Operating costs (in thousands)                      $   19,975     $  25,690     $  31,295
Electric power produced (MWh/D)                          2,097         1,968         2,088
Electric power sold (MWh/D)                              1,918         1,806         1,925
Average sales price per MWh                         $    40.79     $   47.00     $   50.06
Fuel gas cost per MMBtu (including transportation)  $     2.89     $    4.20     $    4.49
Estimated natural gas volumes consumed to produce
electricity (MMBtu/D)(1)                                15,415        15,229        18,171

Electricity sales in 2012 decreased 14% compared to 2011. In 2012 and 2011, electricity sales included retroactive payment adjustments for capacity of $1.3 million and $4.1 million, respectively, from our electricity customers. As a result of our previously disclosed global settlement with various parties that became effective on November 23, 2011, we received retroactive payments for firm capacity that had been originally paid at "as available" capacity rates, and these payments represent the difference in rates over the disputed period. Excluding the retroactive payment adjustments, electricity sales in 2012 would have decreased 7% compared to 2011. The decrease in electricity sales was primarily due to a 13% decrease in the average sales price of electricity, partially offset by a 6% increase in electric power sold period over period primarily due to a decrease in the downtime of our cogeneration facilities in 2012 compared to 2011. Electricity operating costs in 2012 decreased 22% compared to 2011 primarily due to a 31% decrease in fuel gas cost, partially offset by a 1% increase in fuel gas volumes purchased.

Electricity sales increased 1% in 2011 compared to 2010 primarily due to the retroactive capacity refund of $4.1 million received in December 2011 from one . . .

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